Only a portion of the oil originally present in a subterranean oil-bearing formation is recovered during the primary production cycle. During primary production only the natural pressure present in the formation is exploited for oil recovery. Waterflooding is the most commonly used secondary recovery process. Injection of water into strategically located wells serves to revive formation pressure and to physically displace oil present in the subterranean formation. However, large volumes of the original in-place hydrocarbons, in some instances as much as 50%, still remain trapped in the reservoir even after waterflooding.
Numerous approaches have been taken to try and recover the residual oil after waterflooding has ceased to be economical. These have included thermal methods such as steam stimulation, fire flooding and in situ combustion. Recovery processes have also utilized components such as nitrogen, carbon dioxide and light hydrocarbon gases to displace residual oil. For formations containing lighter oil deposits, for example, oil-bearing strata where the API gravity of the oil phase is 10 or greater, the dominant method for enhanced oil recovery has been carbon dioxide injection. In some limited instances where the oil producing strata are at substantially greater depths, nitrogen has been used because greater injection pressures are required. In some locations, particularly parts of Alaska and Canada, light hydrocarbon gases which are generated during the oil recovery step are subsequently reinjected for pressure maintenance and for the recovery of additional oil.
In a miscible flooding operation, the injected solvent is capable of forming a single phase solution with the oil in place, which assists in the oil recovery step. Barring any areal sweep inefficiencies, a miscible drive process can effectively displace oil from the parts of the reservoir through which the solvent flows because a single phase is flowing through the formation. In multiple phase flow, interfaces and the retentive forces of capillarity and interfacial tension have to be overcome before the oil can be displaced. Carbon dioxide is the most commonly used solvent in miscible displacement processes. Under certain appropriate conditions of oil gravity and reservoir temperature and pressure, carbon dioxide is first contact miscible with reservoir hydrocarbons. However, if the reservoir temperature is too high, or the reservoir pressure is not high enough, carbon dioxide may not be first contact miscible with the in-place hydrocarbons. In such instances, multiple contact miscibility between the injected carbon dioxide and the in-place hydrocarbons is still possible. During multiple contact miscibility, the carbon dioxide initially injected continues to strip light hydrocarbons from successive contacts with the in-place hydrocarbons, until it achieves a composition suitable for miscibility with the reservoir fluids. When carbon dioxide first contacts reservoir hydrocarbons, it dissolves in the oil phase, thus swelling the hydrocarbon fluids and reducing their viscosity. Both of these effects have a very positive influence on final oil production. By swelling the oil, an expansion of the oil phase into existing flowing channels facilitates additional oil recovery. By lowering oil viscosity, the energy required to move the oil through the pore structures in the reservoir is minimized, and again more oil is accessed by the displacing solvent. These two positive effects attend the injection of carbon dioxide irrespective of the displacement process that results. Both nitrogen and light hydrocarbons will show similar positive effects when injected into oil bearing formation. Nitrogen, however, is less soluble in the oil phase. Therefore, oil swelling and viscosity reduction of the in-place hydrocarbons is not as pronounced. Additionally, much higher pressures (relative to carbon dioxide) are required for nitrogen to achieve first or multiple contact miscibility with crude oils.
Light hydrocarbons are excellent displacing solvents for oil because they are very soluble in the oil, causing high swelling and viscosity reduction, and readily achieve first or multiple contact miscibility with the reservoir hydrocarbons. However, the expense of procuring these light hydrocarbons, and of leaving large volumes of these hydrocarbons behind in the reservoir during the displacement process precludes the extensive use of such solvents, except in remote locations where no market for the hydrocarbons is available.
Unfortunately, the efficacy of all these displacement processes is severely hampered by the low viscosity of the injected miscible solvent phase at reservoir conditions. For example, at typical reservoir conditions such as 95.degree. F. and 3500 psia, the injected miscible solvent can be expected to have a viscosity of less than 0.1 centipoise (cp), whereas most reservoir fluids have viscosities ranging in value from 0.4 cp to 8 cp. Under these conditions a very adverse mobility ratio between displaced and displacing fluids is created, resulting in fingering of the displacing fluid through the in-place reservoir fluids and early breakthrough of the injected solvent. This viscosity disparity tends to become even more pronounced at higher temperatures.
An additional fact to consider is reservoir heterogeneity, e.g., high permeability streaks that tend to take the bulk of the injected miscible solvent. This combination of low solvent viscosity and high permeability thief zones tends to aggravate the viscous fingering problem, leading to early breakthrough of solvent, poor areal sweep, and costly solvent recycle processes.
Even in the absence of high permeability streaks, the need for mobility control would be greatly reduced because the multiple contact process will automatically result in a gradual viscosity gradient sufficient to counter the viscosity difference between the injected solvent and the reservoir fluids. By offering a convenient path of least resistance, the high permeability streaks disrupt the formation of a gradual enriched solvent bank with the appropriate viscosity gradient that would minimize solvent breakthrough due to viscous fingering.
U.S. Pat. No. 4,913,235 teaches a method for directly viscosifying the injected solvent by the addition of a polydimethylsiloxane type polymer and a cosolvent such as toluene. U.S. Pat. No. 4,828,029 teaches a method for surfactant transport in order to facilitate in situ foam generation for solvent mobility control. Thus both patents attempt to address the poor areal sweep of the injected solvent due to its low viscosity.
The direct viscosification process described in U.S. Pat. No. 4,913,235 is effective in countering the adverse areal sweep resulting from a viscosity difference between injected solvent and reservoir fluids, but will be relatively ineffectual in minimizing the preferential movement of the injected solvent through the high permeability zone. Correct remedial action for a high permeability zone requires that the zone be plugged in order to force the injected solvent to sweep past it and thus contact a larger volume of the reservoir. For this reason, the process described in U.S. Pat. No. 4,828,029 will be more effective, because the surfactant can be delivered preferentially to the high permeability zone in sufficient concentration to create a foam or emulsion capable of the desired plugging action.
Both of these patents deal with a direct modification of the injected miscible displacement solvent as opposed to some other injected or in situ phase. However, because of the poor solvent properties of most injected solvent phases, the success of the processes described in these two patents is dependent on the use of cosolvents in sufficient amounts to enhance the solubilizing capability of the miscible solvent at reservoir conditions of temperature and pressure. The cheapest miscible drive solvents would be carbon dioxide or methane, or mixtures of the two. However, depending on the reservoir conditions of temperature and pressure, carbon dioxide or methane, or mixtures of the two could prove inadequate for the generation of multiple contact miscibility with reservoir hydrocarbons. In such cases, light hydrocarbons in the C2 through C8 range could be deliberately added to the primary miscible drive solvent to enhance it solubilizing characteristics. Additionally, when solvent breakthrough occurs, usually due to the combined effects of viscous fingering and reservoir heterogeneity, an initially lean injected gas could be substantially enriched with light hydrocarbons stripped from the reservoir fluids. Occasionally these heavier hydrocarbons will be stripped out of the primary solvent on the surface before it is reinjected, but frequently none or only some of the higher molecular weight hydrocarbons are removed from the solvent prior to reinjection. For the purpose of this invention, all the instances of drive solvent enrichment, whether deliberate or incidental, would represent a primary injection solvent reinforced with cosolvents.
For the further purpose of this invention, cosolvents are necessary because the chemical nature of the solvents and solutes involved is such that no hydrogen bonding or dipole-dipole type interactions are feasible between solutes, such as surfactants, or polymers and primary displacement solvents, such as carbon dioxide or methane or nitrogen or mixtures of the same. Consequently, solute solubility is dictated entirely by a matching of the solubility parameter of the solute to that of the solvent. For solvents such as carbon dioxide at typical reservoir conditions, the value of the solubility parameter would be in the range of 6.9 or less, and would decrease with increasing temperature, though increasing pressure would have a beneficial effect. The value of the solubility parameter of hydrocarbon solvents will be slightly higher, and will increase as the contribution from the higher molecular weight components increases.
Unfortunately, the value of the solubility parameter for most surfactants and polymers of interest is considerably greater than 6.9, which necessitates the use of cosolvents in order to increase the solvent solubility parameter to bring it into a more workable range. The remarkable success of the polymer solution process described in U.S. Pat. No. 4,913,235 is dependent on the low value of the solubility parameter for the polydimethylsiloxane polymers, so that solubility at reasonable cosolvent concentrations is possible. The fact that the solubility parameter of the injected solvent decreases with increasing temperature is significant because it dictates the cosolvent concentration required for a particular application. Thus, more cosolvent will be needed to keep a solute, such as a surfactant or polymer, in solution at a given temperature, e.g. 150.degree. F., than would be needed to achieve solubility at a lower temperature, e.g., 130.degree. F.
There still exists a need in the industry for a system that delivers a mobility control agent into the higher permeability zones of a reservoir where it is most needed.